US9046626B2 - Performing reverse time imaging of multicomponent acoustic and seismic data - Google Patents
Performing reverse time imaging of multicomponent acoustic and seismic data Download PDFInfo
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- US9046626B2 US9046626B2 US13/345,412 US201213345412A US9046626B2 US 9046626 B2 US9046626 B2 US 9046626B2 US 201213345412 A US201213345412 A US 201213345412A US 9046626 B2 US9046626 B2 US 9046626B2
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/38—Seismology; Seismic or acoustic prospecting or detecting specially adapted for water-covered areas
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/60—Analysis
- G01V2210/67—Wave propagation modeling
- G01V2210/679—Reverse-time modeling or coalescence modelling, i.e. starting from receivers
Definitions
- Seismic exploration involves surveying subterranean geological formations for hydrocarbon deposits.
- a survey typically involves deploying seismic source(s) and seismic sensors at predetermined locations.
- the sources generate seismic waves, which propagate into the geological formations creating pressure changes and vibrations along their way. Changes in elastic properties of the geological formation scatter the seismic waves, changing their direction of propagation and other properties. Part of the energy emitted by the sources reaches the seismic sensors.
- Some seismic sensors are sensitive to pressure changes (hydrophones), others to particle motion (e.g., geophones), and industrial surveys may deploy only one type of sensors or both.
- the sensors In response to the detected seismic events, the sensors generate electrical signals to produce seismic data. Analysis of the seismic data can then indicate the presence or absence of probable locations of hydrocarbon deposits.
- marine surveys Some surveys are known as “marine” surveys because they are conducted in marine environments. However, “marine” surveys may be conducted not only in saltwater environments, but also in fresh and brackish waters.
- a “towed-array” survey an array of seismic sensor-containing streamers and sources is towed behind a survey vessel.
- Other types of configuration are possible (such as a survey using a seabed cable, for example).
- a technique includes performing reverse time imaging to determine an image in a region of interest.
- the reverse time imaging includes modeling a pressure wavefield and a gradient wavefield in the region of interest based at least in part on particle motion data and pressure data acquired by sensors in response to energy being produced by at least one source.
- FIG. 1 is a schematic diagram of a seismic acquisition system according to some embodiments.
- FIG. 2 illustrates a model for performing the reverse time imaging according to some embodiments.
- FIGS. 3 , 4 , 5 , 6 and 7 are flow diagrams depicting reverse time imaging techniques using pressure and particle motion data according to some embodiments.
- FIG. 8 is a schematic diagram of a data processing system according to some embodiments.
- FIG. 1 depicts a marine-based, towed seismic data acquisition system 10 , which includes a survey vessel 20 that tows one or more seismic streamers 30 (one streamer 30 being depicted in FIG. 1 , as a non-limiting example) behind the vessel 20 .
- the streamers 30 may be arranged in a spread in which multiple streamers 30 are towed in approximately the same plane at the same depth.
- the streamers may be towed at multiple and/or variable depths, such as in an over/under spread, for example.
- the seismic streamers 30 may be several thousand meters long and may contain various support cables (not shown), as well as wiring and/or circuitry (not shown) that may be used to support communication along the streamers 30 .
- each streamer 30 includes a primary cable into which is mounted seismic sensors that record seismic signals.
- the streamers 30 contain seismic sensors 58 , such as pressure and particle motion sensors that are constructed to acquire pressure data and particle motion data, respectively.
- the marine seismic data acquisition system 10 further includes seismic sources 40 (two seismic sources 40 being depicted in FIG. 1 , as an example), such as air guns and the like.
- the seismic sources 40 may be coupled to, or towed by, the survey vessel 20 .
- the seismic sources 40 may operate independently of the survey vessel 20 , in that the sources 40 may be coupled to other vessels or buoys, as just a few examples.
- acoustic signals 42 (an acoustic signal 42 being depicted in FIG. 1 , as an example), often referred to as “shots,” are produced by the seismic sources 40 and are directed down through a water column 44 into strata 62 and 68 beneath a water bottom surface 24 .
- the acoustic signals 42 are reflected from the various subterranean geological formations, such as, for example, a geological formation 65 that is depicted in FIG. 1 .
- the incident acoustic signals 42 that are created by the sources 40 produce corresponding reflected acoustic signals, or pressure waves 60 , which are sensed by the seismic sensors 58 .
- the seismic waves that are received and sensed by the seismic sensors 58 include “up going” seismic waves that propagate to the sensors 58 after reflections at the subsurface, as well as “down going” seismic waves that are produced by reflections of the pressure waves 60 from an air-water boundary, or free surface 31 .
- the seismic sensors 58 generate signals (digital signals, for example), called “traces,” which indicate the acquired measurements of the pressure wavefield and particle motion.
- the traces are recorded and may be at least partially processed by a signal processing unit 23 that is deployed on the survey vessel 20 , in accordance with some embodiments.
- a particular seismic sensor 58 may be a hydrophone that provides a trace, which corresponds to a measure of a pressure wavefield; and another sensor 58 may provide (depending on the particular embodiment) one or more traces that correspond to one or more measured components of particle motion.
- the goal of the seismic acquisition is to build up an image of a survey area for purposes of identifying subterranean geological formations, such as the geological formation 65 , for example.
- Subsequent analysis of the representation may reveal probable locations of hydrocarbon deposits in subterranean geological formations.
- portions of the analysis of the representation may be performed on the seismic survey vessel 20 , such as by the signal processing unit 23 .
- the representation may be processed by a seismic data processing system that may be, for example, located on land or on the vessel 20 .
- Reverse time imaging may be used for purposes of constructing an image of a particular subterranean geologic region of interest based on the acquired seismic data.
- the seismic data may be processed for purposes of removing the free surface multiples and the ghost arrivals before performing the reverse time imaging, it has been discovered that the information that is present in the ghost and free surface multiple energy may aid in improving the quality of the image. Referring to FIG.
- an image (called “I(x)” or simply “I” herein) of a particular region of interest may be constructed using data acquired by particle motion and pressure sensors that are referred to as “receivers 106 .”
- the receivers 106 acquire particle motion and pressure measurements resulting from energy that is produced by sources 102 reflecting from various subsurface interfaces in the region of interest.
- the receivers 106 are associated with a corresponding boundary 108
- the sources 102 are denoted by a corresponding boundary 104
- normals to the source and receiver surfaces are denoted by n s and n r , respectively.
- image points 107 depicted as non-limiting examples
- example image points 107 a and 107 c representing an image of zero (i.e., an image away from interfaces or scatterers)
- example image point 107 d being a nonzero image point.
- a technique 120 includes acquiring (block 124 ) pressure data and particle motion data and subsequently processing the acquired data to perform reverse time imaging to determine an image in a region of interest. More specifically, the technique 120 includes determining (block 128 ) pressure and gradient wavefields in a region of interest based on pressure and particle motion data and applying (block 132 ) the pressure and gradient wavefields to an imaging condition to determine the image for the region of interest.
- G S time domain-based total receiver wavefield
- x represents an arbitrary position in the region of interest.
- an imaging condition (called “I grad (x)” herein) may be defined as follows for a nonlinear source-receiver migration:
- I grad ⁇ ( x ) ⁇ ⁇ ⁇ 2 ⁇ ⁇ R ⁇ ⁇ ⁇ ⁇ D s ⁇ 1 i ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ [ ⁇ x s ⁇ G S ⁇ ( x , x S , ⁇ ) ⁇ G 0 * ⁇ ( x , x S , ⁇ ) ] ⁇ n s ⁇ d 2 ⁇ x s ⁇ ⁇ ⁇ d ⁇ ⁇ - ⁇ ⁇ 2 ⁇ ⁇ R ⁇ ⁇ ⁇ ⁇ ⁇ D s ⁇ 1 i ⁇ ⁇ ⁇ ⁇ ⁇ ⁇ [ G S ⁇ ( x , ⁇ ) ⁇ ⁇ x s ⁇ G 0 * ⁇ ( x , x S , ⁇ ) ] ⁇ n s ⁇ d 2 ⁇ x s ⁇ ⁇ ⁇ ⁇ ⁇
- ⁇ represents the angular frequency
- ⁇ represents the spatially-varying medium density at the source surface
- ⁇ represents the real component
- ⁇ represents a gradient
- ⁇ s represents the boundary of the region of interest (see also FIG. 2 )
- n S represents the normal to the source (see also FIG. 2 )
- G 0 represents the background model
- * represents the conjugation operator.
- I grad RTM (x) A simplified imaging condition for linear source-receiver migration may be described as follows:
- the inner integral represents a summation over physical source positions, thereby denoting shot-profile imaging methods.
- the methods may be also applied to a receiver profile geometry by interchanging the domains of integration between the imaging conditions in Eqs. 2 and 3 and the corresponding extrapolation integrals, which are discussed below.
- the outer integrals in Eqs. 2 and 3 denote an inverse Fourier transform, which is evaluated at zero time. It is noted that the gradients (denoted by the ⁇ x s operator) are evaluated with respect to the source coordinates.
- Equations 2 and 3 describe techniques for evaluating imaging conditions for linear and nonlinear reverse time migrations and cover various types of vector acoustic data as follows. More specifically, a technique 140 that is depicted in FIG. 4 may be used in accordance with Eqs. 2 and 3 to evaluate the imaging condition. Pursuant to the technique 140 , the receiver wavefields are cross-correlated with the source wavefields, pursuant to block 142 .
- the terms of Eq. 2 set forth the cross-correlation for both pressure and dipole sources.
- Eq. 3 are used, which correspond to the first two terms of Eq. 2. For linear imaging from pressure only sources, only the second term in Eq. 3 is used; and for the linear imaging for dipole-only sources, only the first term in Eq. 3 is used.
- the imaging condition separates and controls the image contributions arising from the data from either monopole pressure sources; dipole or gradient pressure sources; or both types of sources. This holds true for both nonlinear imaging and reverse time migration using vector acoustic data.
- the imaging conditions take into account both pressure and dipole/gradient recordings from the receivers. The receiver dual field information, at this point, is implicitly accounted for in the extrapolated receiver fields, as further described below.
- the receiver and source wavefields may be extrapolated using the above-described imaging conditions, as set forth below.
- First set forth below is a description of a linearized wavefield extrapolation using vector acoustic data.
- the wavefield extrapolation obtains the subsurface domain wavefields that are present in the imaging conditions that are set forth in Eqs. 2 and 3.
- the linear receiver wavefield extrapolations receive the subsurface fields G S (x,x S ) from the actual data recorded between the physical sources x S and receivers x R , as described below:
- G S (x r , x S , ⁇ ) represents a recorded receiver pressure wavefield due to a monopole pressure source
- ⁇ x r G S (x r , x S , ⁇ ) represents the acquired particle motion measurement of the gradient receiver wavefield due to the monopole pressure source
- ⁇ x s G S (r r , x S , ⁇ ) represents a measurement recorded by the pressure receivers due to a dipole pressure source
- ⁇ x s ⁇ x r G S (x r , x S , ⁇ ) represents the particle motion measurement by the receivers due to the dipole source.
- monopole and dipole sources inject energy.
- the energy that is injected depends on the acquired pressure and partition motion data.
- a reverse time imaging technique 150 may be applied for purposes of determining an image using pressure and gradient measurements.
- the technique 150 includes injecting monopole source energy based on pressure data, pursuant to block 154 , and injecting monopole source energy based on particle motion data, pursuant to block 158 .
- the resulting subsurface wavefields may then be combined, pursuant to block 162 .
- an image may be determined based on the combined pressure wavefields derived in block 162 and, as also indicated in bock 164 , possibly also based on combined pressure wavefields that are derived in a technique 180 (see FIG. 6 ).
- the extrapolation of the source wavefields of, i.e., the wavefields denoted by “G O ,” may be performed by forward simulation of the background responses with synthetic sources at each source location.
- dipole sources may inject energy based on the pressure and particle motion data.
- a reverse time imaging technique 180 includes injecting energy produced by dipole sources that are disposed at the boundary of the region of interest based on pressure data, pursuant to block 184 , and injecting (block 188 ) energy that is produced by dipole sources that are disposed at the boundary of the region of interest based on particle motion data.
- the resulting subsurface wavefields may then be combined (block 192 ).
- an image may be determined based on the combined pressure wavefields derived in block 192 and, as also indicated in bock 194 , possibly also based on combined pressure wavefields that are derived in the technique 150 (see FIG. 5 ).
- nonlinear receiver wavefield extrapolation may be described as set forth below, in accordance with other embodiments:
- the following technique may be used for nonlinear extrapolation, which jointly uses pressure and gradient data.
- the technique 150 ( FIG. 5 ) or 180 ( FIG. 6 ) may be performed using a reference part of a wavespeed model, which is a relatively smooth wavespeed model that has few or a limited number of discontinuities. From this extrapolation, the real part of the fields are determined, which provides the first two terms of Eqs. 5 and 6.
- receiver wavefield extrapolation is performed, pursuant to either the technique 150 or 180 using the full wavespeed model.
- the full wavespeed model contains all of the known/desired discontinuities.
- a technique 200 includes determining (block 204 ) first components of receiver pressure wavefields using a first version of a wavespeed model (a relatively smoother version or an initial baseline wavespeed model, as non-limiting examples) and subsequently determining (block 208 ) second components the receiver pressure wavefields using a second version of the wavespeed model (a relatively fuller, or complete, version, as a non-limiting example).
- a data processing system 320 may contain a processor 350 for purposes of processing particle motion and pressure data for purposes of performing reverse time imaging to determine an image in a geological subterranean region of interest.
- the processor 350 may acquire pressure data and particle motion data, determine pressure and gradient wavefields in a region of interest based on the pressure and particle motion data and apply the determined pressure and gradient wavefields to imaging condition to determine an image for a region of interest.
- the processor 350 may be formed from one or more microprocessors and/or microprocessor processing cores.
- the processor 350 may be disposed on a streamer 30 (see FIG. 1 ), located on the vessel 20 (see FIG. 1 ), located at a land-based processing facility, disposed at a well site in which a sensor cable is deployed in a well, etc., depending on the particular embodiment.
- the data processing system 320 may be a distributed processing system, in accordance with some embodiments.
- the processor 350 may be coupled to a communication interface 360 for purposes of receiving pressure and particle motion data.
- the communication interface 360 may be a Universal Serial Bus (USB) interface, a network interface, a removable media interface (a flash card, CD-ROM interface, etc.) or a magnetic storage interface (IDE or SCSI interfaces, as non-limiting examples).
- USB Universal Serial Bus
- the communication interface 360 may take on numerous forms, depending on the particular embodiment.
- the processor 350 is coupled to a memory 340 , which stores program instructions 344 , which when executed by the processor 350 , may cause the processor 350 to perform various tasks of one or more of the techniques that are disclosed herein, such as the techniques 120 , 140 , 150 , 180 and/or 200 , as non-limiting examples.
- the memory 340 is a non-transitory memory and may take on numerous forms, such as semiconductor storage, magnetic storage, optical storage, phase change memory storage, capacitor-based storage, etc., depending on the particular implementation.
- the memory 340 may be formed from more than one of these non-transitory memories, in accordance with some embodiments.
- the processor 340 may also, for example, store preliminary, intermediate and/or final results obtained via the execution of the program instructions 344 as data 348 in the memory 340 .
- the data processing system 320 is merely an example of one out of many possible architectures for processing the seismic data in accordance with the techniques that are disclosed herein. Moreover, the data processing system 320 is represented in a simplified form, as the processing system 320 may have various other components (a display to display initial, intermediate or final results of the system's processing, as a non-limiting example), as can be appreciated by the skilled artisan. Thus, many variations are contemplated and are within the scope of the appended claims.
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Abstract
Description
G S(x,x,τ=0), Eq. 1
where “x” represents an arbitrary position in the region of interest. In view of the total receiver wavefield GS(x,xS,τ=0), an imaging condition (called “Igrad(x)” herein) may be defined as follows for a nonlinear source-receiver migration:
where “ω” represents the angular frequency; “ρ” represents the spatially-varying medium density at the source surface; “” represents the real component; “∇” represents a gradient; “∂ s” represents the boundary of the region of interest (see also
In Eq. 4, the integration is carried out over the receiver surfaces corresponding to each individual shot, and the gradients are taken with respect to receiver coordinates. The source-gradient receiver wavefield may be described as follows:
for the pressure receiver wavefield due to pressure sources, and
for the pressure receiver wavefield due to dipole sources.
Claims (20)
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US13/345,412 US9046626B2 (en) | 2011-01-10 | 2012-01-06 | Performing reverse time imaging of multicomponent acoustic and seismic data |
PCT/US2012/020603 WO2012096871A2 (en) | 2011-01-10 | 2012-01-09 | Performing reverse time imaging of multicomponent acoustic and seismic data |
NO20130967A NO20130967A1 (en) | 2011-01-10 | 2013-07-11 | Performing reverse time mapping of acoustic and seismic multicomponent data |
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US13/345,412 US9046626B2 (en) | 2011-01-10 | 2012-01-06 | Performing reverse time imaging of multicomponent acoustic and seismic data |
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Cited By (1)
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US11467306B2 (en) * | 2017-08-11 | 2022-10-11 | Pgs Geophysical As | Processes and systems for correcting receiver motion and separating wavefields in seismic data recorded with multicomponent streamers |
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US9046626B2 (en) | 2011-01-10 | 2015-06-02 | Westerngeco L.L.C. | Performing reverse time imaging of multicomponent acoustic and seismic data |
WO2012160430A2 (en) * | 2011-05-24 | 2012-11-29 | Geco Technology B.V. | Data acquisition |
US9405028B2 (en) | 2013-02-22 | 2016-08-02 | Ion Geophysical Corporation | Method and apparatus for multi-component datuming |
US20140379266A1 (en) * | 2013-06-25 | 2014-12-25 | Westerngeco L.L.C. | Processing survey data containing ghost data |
US20160327668A1 (en) * | 2014-01-14 | 2016-11-10 | Westerngeco Llc | Interferometry-bsed imaging and inversion |
WO2015108862A1 (en) | 2014-01-14 | 2015-07-23 | Westerngeco Llc | Transmission without reverberation by iterative incomplete time-reversal |
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US11467306B2 (en) * | 2017-08-11 | 2022-10-11 | Pgs Geophysical As | Processes and systems for correcting receiver motion and separating wavefields in seismic data recorded with multicomponent streamers |
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US20120183176A1 (en) | 2012-07-19 |
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NO20130967A1 (en) | 2013-07-25 |
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